Downhole tool having an axial passage and a lateral fluid passage being opened/closed

ABSTRACT

A downhole tool operatively associated with a downhole pump for use in artificial lift applications comprises a body having a throughbore forming an axial flow passage and a plurality of lateral ports forming a lateral flow passage, a valve seat for co-operating with a valve member and a sleeve member. In use, the downhole tool is run into a borehole, such as an oil and/or gas production well borehole, as part of a tubing string, the downhole tool being configured to permit selective axial passage of fluid through the downhole tool while lateral passage of fluid is prevented, the downhole tool being operable to move from the first, closed, configuration to the second, open, configuration in response to the activation event to divert fluid through the lateral flow passage into an annulus between the downhole tool and the borehole.

FIELD

This disclosure relates to a downhole tool and method. More particularly, but not exclusively, embodiments of this disclosure relate to a downhole tool operatively associated with a downhole pump for use in artificial lift applications.

BACKGROUND

During extraction of natural resources from subterranean reservoirs, which may include hydrocarbon fluids and/or water and/or gas, there often exists a pressure differential between the reservoir and the earth's surface (known as hydrostatic head) which must be overcome in order to produce the fluid resources to surface. In the hydrocarbon production industry, this process is commonly known as “artificial lift”.

Artificial lift can be achieved by using a variety of means including the use of pumps such as a progressive cavity pump (PCP). PCP's are positive displacement pumps and as such there is physical contact between their constituent pressure inducing components. A typical PCP comprises a helical steel rotor and a rubber stator having an internal eccentric helical profile closely matching that of the rotor. The stator is typically encapsulated in steel tubing that forms a lower portion of a tubing string that runs from the reservoir to the surface. The rotor is typically connected to the bottom of a rod string that also runs to surface. The rotor and rod string have a smaller outside diameter than the inside diameter of the aforementioned tubing string. The rotor and rod string are run in from surface through the bore of the tubing string and positioned such that the rotor is located within the stator. This arrangement results in a series of cavities along the length of the PCP. The rod string is connected to a suitable rotary drive at surface which powers rotation of the rod string and rotor assembly within the stator when the PCP is in use. The use of rod guides or centralisers along the length of the rod string is typical to maintain the rod string in a relatively central position within the tubing string. This rotation causes fluid in the cavities to move upward into the tubing string resulting in a gradual increase in pressure between the PCP inlet and discharge. This positive displacement of fluid overcomes the hydrostatic head and provides the necessary lift to produce the reservoir fluids to surface.

PCP's may be used to produce water or hydrocarbon fluids to surface that may be light and thin or heavy and highly viscous, and often these applications produce large quantities of sand and other solids along with the produced fluids. PCP run-life is largely dependent on the amount of solids produced through the pump.

Often, sand and other solids produced through a PCP will suspend, entrained in the fluid column above the PCP, within the tubing string. If operation of the PCP is stopped, which may occur for a variety of reasons including planned maintenance or unplanned power cuts, these solids can settle on top of the PCP, forming a sand plug on top of the pump. With applications that produce excessive amounts of sand/solids, the solids may also enter the upper stages (cavities) of the pump. If a sand plug has formed, then when the PCP is restarted it initially runs dry as pressure gradually increases to the point at which the sand plug is dislodged. Due to the intimate contact between the rotor and the stator, this period of dry running can seriously damage the rubber stator effectively destroying the pump.

Historically, this has been avoided by retracting the rotor from the stator to dislodge the sand plug and allow it to fall through the stator back into the reservoir. However, such a “work-over” operation requires specialist equipment and is extremely costly and time consuming. When operation of the pump is stopped, the large volume of fluid inside the tubing string will tend to drop or “u-tube” back down towards the static fluid level in the reservoir to equalise pressure in the system. With conventional PCP completions this “u-tubing” fluid column acts on the rotor with a very high pressure. This pressure will force the rotor/rod string to rotate inside the stator in the opposite direction to the PCP's normal operational mode, a condition known as “back-spin”. This is not desirable as it can damage the rod string or surface drive equipment and can take significant time to subside.

Furthermore, if sand or other solids have entered the upper stages of the PCP, in addition to retracting the rotor from the stator to clear any sand plug, there will be a requirement to pump fluids through the stator as the rotor is retracted to flush out these solids. These procedures are commonly known as “back-flush” or “flush-by” operations. In order for these operations to be completed the rotor may be easily retractable, and the integrity of the tubing string may be maintained from surface all the way to the stator. All aspects of these operations can be costly and time consuming.

SUMMARY

Aspects of the present disclosure relate to a downhole tool and method and more particularly, but not exclusively, to a downhole tool operatively associated with a downhole pump and method for use in artificial lift operations.

According to a first aspect, there is provided a downhole tool comprising:

a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and

a lateral flow passage disposed through the body,

wherein the downhole tool is operable between a first, closed, configuration in which fluid communication through the lateral flow passage is prevented and a second, open, configuration in which fluid communication through the lateral flow passage is permitted, the downhole tool being configured to normally define the first, closed, configuration.

The downhole tool may comprise a valve arrangement configured to permit selective fluid communication through the axial flow passage. When the downhole tool defines the second, open, configuration permitting fluid communication through the lateral flow passage, the downhole tool may prevent fluid communication through the axial flow passage. Beneficially, such an arrangement permits fluid to be diverted through the lateral flow passage but prevent back-flow of fluid through the axial flow passage.

The downhole tool may comprise a sleeve member. The sleeve member may be operatively associated with the lateral flow passage. The downhole tool may be configured so that in the first, closed, configuration, the sleeve member prevents fluid communication through the lateral flow passage. The downhole tool may be configured so that in the second, open, configuration the sleeve member permits fluid communication through the lateral flow passage.

The downhole tool may be operable to move from the first, closed, configuration to the second, open, configuration in response to an activation event.

In use, the downhole tool may be run into a borehole, such as an oil and/or gas production well borehole, as part of a tubing string, the downhole tool being configured so that the valve arrangement permits selective axial passage of fluid through the downhole tool while lateral passage of fluid is prevented, the downhole tool being operable to move from the first, closed, configuration to the second, open, configuration in response to the activation event to divert fluid through the lateral flow passage.

The activation event may take a number of different forms.

The activation event may comprise a force acting on the sleeve member.

The activation event may comprise a fluid pressure force acting on the sleeve member. The fluid pressure force may comprise a differential pressure force acting on the sleeve member, for example between fluid uphole of the sleeve member and fluid downhole of the sleeve member. In particular embodiments, the activation event may comprise a fluid pressure force acting on the sleeve member as a result of shut down of a downhole pump with which the downhole tool is operatively associated.

In use, the downhole tool may be operatively associated with a downhole pump and the valve arrangement of the downhole tool may be configured to permit fluid passage from the downhole pump towards surface or other uphole location via the axial flow passage while preventing back-flow. During such operations, the downhole tool is configured with the lateral flow passage in the closed configuration, maintaining integrity of the downhole tool and the associated tubing string. In the event pump operation ceases, the downhole tool may be operable to move to the second, open, configuration to divert fluid uphole of the valve arrangement through the lateral flow passage.

Embodiments of the present disclosure provide a number of benefits over conventional equipment and techniques.

For example, in situations where solids have settled and/or a sand plug has formed above the downhole pump, when the downhole pump is re-started it initially runs dry—since pressure gradually increases to the point at which the sand plug can be dislodged. However, due to the intimate contact between the pump's rotor and the stator, this initial period of dry operation can result in significant damage to the pump, and associated equipment.

In embodiments of the present disclosure, however, the ability to selectively divert fluid through the lateral flow passage facilitates increased run-life of an associated downhole pump by obviating damage that may otherwise occur from settlement of solids and/or the formation of a sand plug on top of the downhole pump when pump operation ceases or is insufficient to lift such solid material to surface.

Embodiments of the present disclosure further obviate the need to perform work-over operations, thereby providing significant cost and time saving benefits for an operator compared to conventional techniques and technology.

For example, when seeking to dislodge a sand plug, the conventional technique is to perform a work-over operation whereby the pump's rotor is retracted from the stator, allowing the sand and other solids to fall through the pump's stator back into the reservoir. In addition to retracting the rotor from the stator to clear the solids/sand plug, there is a requirement to flush out the solids through the stator as the rotor is retracted, known as a “back-flush” or “flush-by” operation. Such work-over operations require the rotor to be easily retractable, but also that the integrity of the tubing string is maintained from surface all the way to the stator.

In embodiments of the present disclosure, the ability to maintain tubing string integrity during normal operation and selectively divert fluid through the lateral flow passage obviates the requirement to perform such work-over operations.

Embodiments of the present disclosure may alternatively or additionally provide a number of other benefits.

For example, when operation of the downhole pump is stopped to perform a work-over operation, the large volume of fluid inside the tubing string will tend to drop or “u-tube” back down towards the static fluid level in the reservoir to equalise pressure. With conventional downhole pump equipment, this “u-tubing” fluid column acts on the pump's rotor with a very high pressure, and forces the rotor to rotate inside the stator in the opposite direction to the pump's normal operational mode, a condition known as “back-spin”. This is not desirable as it can damage the rod string or surface drive equipment and can take significant time to subside.

In embodiments of the present disclosure, however, this high pressure acts on the sleeve member to transition the downhole tool from the first configuration to the second, open, configuration; diverting the fluid into the annulus. A downhole tool according to embodiments of the present disclosure may thus facilitate increased pump run-life by obviating or mitigating back-spin of the pump, while supporting and simplifying back-flush operations, if required.

Still further, embodiments of the present disclosure may permit fluid to be diverted back to the formation via the annulus, facilitating increased pump run-life by mitigating the effects of over production and pump-off in which well fluids cannot permeate through the reservoir formation quickly enough to replace fluids that have been produced to surface and which results in the pump running dry, with consequential significant damage to the pump and associated equipment.

Moreover, embodiments of the present disclosure may support and simplify well treatment operations to optimise or stimulate production, since the annulus may accessed via the lateral flow passage.

The activation event may alternatively or additionally comprise a fluid pressure force resulting from fluid directed through the axial flow passage from surface or other uphole location. This fluid may, for example but not exclusively, comprise a well treatment fluid or the like. Embodiments of the present disclosure thus support chemical treatment or injection operations without the need to perform work-over operations, such as retracting the pump's rotor from the stator described above.

As described above, the downhole tool may be configured to normally define the first, closed, configuration in which the sleeve member prevents fluid communication through the lateral flow passage. In use, the downhole tool may be configured to automatically revert to its normal condition, that is, the first, closed, configuration after the fluid has been diverted through the lateral flow passage. This normal condition of the downhole tool may be achieved in a number of different ways. In some embodiments, the downhole tool may be biased towards the first, closed, configuration by a biasing member operatively associated with the sleeve member. In use, the biasing member may be operable to act on the sleeve member to urge the sleeve member axially towards a position blocking the lateral flow passage (i.e., its normal condition/position) until the sleeve member is acted on by a force sufficient to overcome the force exerted by the biasing member (i.e., the activation event). The biasing member may comprise a spring element, such as a coil spring, an elastomeric element, a polymeric element or other element configured to bias the sleeve member.

Alternatively, or additionally, the downhole tool may be biased towards the first, closed, configuration, by fluid pressure. For example, the sleeve member may be configured so that an uphole-directed area of the sleeve member exposed to/communicating with an uphole fluid pressure—and which results in a force urging the sleeve member towards the open configuration—is smaller than a downhole-directed area of the sleeve member exposed to/communicating with a downhole fluid pressure. Beneficially, the difference in areas biases or further biases the sleeve member towards closing the lateral flow passage under equal or substantially equal pressure conditions.

As described above, the sleeve member is operatively associated with the lateral flow passage.

The sleeve member may be generally tubular in construction.

In some embodiments, the sleeve member may comprise one or more lateral flow passage, such as a lateral flow port. In such embodiments, the downhole tool may be configured to define the second, open, configuration by aligning the lateral flow passage of the sleeve member with the lateral flow passage of the downhole tool. In particular embodiments, the sleeve member may comprise a solid member i.e., not having a lateral flow passage.

The sleeve member may comprise a unitary construction.

In particular embodiments, the sleeve member may comprise a plurality of components coupled together. For example, the sleeve member may comprise an upper sleeve member portion and a lower sleeve member portion. The upper sleeve member portion and the lower sleeve member portion may be coupled together by at least one of a mechanical coupling arrangement, such as threaded connection, a quick connector, a weld connection, an adhesive bond or other suitable coupling arrangement. The upper sleeve member portion and the lower sleeve member portion may be constructed from the same material or may be constructed from different materials.

The sleeve member may be configured for location within the body. In embodiments comprising the biasing member, the sleeve member may be coupled at its downhole end to the biasing member.

The downhole tool may comprise a stop, such as a no-go, which limits the stroke of the sleeve member in an uphole direction.

In use, the sleeve member is operatively associated with the lateral flow passage and normally adopts a position blocking the lateral flow passage until acted upon by the activation event, following which the sleeve member moves axially to permit fluid to be diverted via the lateral flow passage.

The lateral flow passage may comprise at least one lateral port. In use, the lateral port permits fluid communication between the axial flow passage and the annulus between the outside of the downhole tool and the borehole.

The lateral flow passage may comprise a single lateral port. In particular embodiments, the lateral flow passage may comprise a plurality of lateral ports. Where the lateral flow passage comprises a plurality of lateral ports, two or more of the lateral ports may be arranged circumferentially. Alternatively, or additionally, two or more of the lateral ports may be arranged axially.

The at least one lateral flow port may be of any suitable form. The at least one lateral flow port may be circular or oval in shape. In particular embodiments, the at least one lateral flow port may be rectangular or substantially rectangular in shape.

The valve arrangement may comprise a valve seat. The valve seat may be formed on, or coupled to, a tubular member which forms part of, or which is coupled to, the body.

The tubular member may define a lateral flow passage. In use, the lateral flow passage of the tubular member may provide fluid communication between the axial flow passage of the downhole tool and the sleeve member, in particular the downhole-directed area of the sleeve member. The downhole tool may comprise one or more fluid gallery providing communication between the axial flow passage and the sleeve member. As described above, the difference in areas of the sleeve member biases or further biases the sleeve member towards closing the lateral flow passage under equal or substantially equal pressure conditions, the fluid gallery facilitating communication of fluid to the downhole-directed area of the sleeve member so that both the downhole-directed area and the uphole-directed area of the sleeve member see the same or substantially the same pressure.

The lateral flow passage of the tubular member may comprise at least one lateral port. In use, the lateral port of the tubular member permits fluid communication between the axial flow passage and the flow gallery. The lateral flow passage of the tubular member may comprise a single lateral port. In particular embodiments, the lateral flow passage of the tubular member may comprise a plurality of lateral ports. Where the lateral flow passage of the tubular member comprises a plurality of lateral ports, two or more of the lateral ports may be arranged circumferentially. Alternatively, or additionally, two or more of the lateral ports may be arranged axially.

The valve seat may be configured to minimise or reduce erosion. For example, the valve seat may comprise, or provide mounting for, a hard faced material. The hard faced material may comprise tungsten carbide. Alternatively, or additionally, a profile of the valve seat may minimise or reduce friction.

At least one of the body and the valve seat may be configured to promote high fluid velocity around the valve seat in use. Beneficially, this further assists in preventing or at least mitigating the accretion of solids, such as sand in the downhole tool.

The valve seat may be configured to receive a valve member, sealing engagement between the valve member and the valve seat preventing fluid communication through the axial flow passage.

In use, the valve seat is operatively associated with the valve member, the valve seat configured to co-operate with the valve member to permit selective axial fluid communication through the downhole tool. During artificial lift or other pumping operations, fluid may act on the valve member to unseat the valve member from the valve seat and permit axial fluid communication through the downhole tool. In the event pumping operations cease or where there is insufficient pressure to unseat the valve member, the valve member will engage the valve seat and prevent reverse flow through the downhole tool.

The downhole tool may comprise or may be operatively associated with the valve member.

In some embodiments, the valve member may be coupled to the downhole tool. In particular embodiments, however, the valve member may be disposed on or coupled to the downhole pump. The valve member may be disposed on, or form part of, a rotor of the downhole pump and in particular embodiments the valve member may be disposed on a rod string of the downhole pump.

The valve member may be axially moveable relative to the downhole pump. For example, the valve member may be axially and/or rotatably moveably coupled to the downhole pump. In use, the valve member may be axially moveable relative to the downhole pump, in particular axially moveable relative to the rod string, in response to fluid flow output from the downhole pump.

In particular embodiments, the valve member may comprise a floating valve member. The valve member may be freely moveable relative to the body of the downhole tool. The valve member may be freely axially moveable relative to the body of the downhole tool. The valve member may be freely rotatably moveable relative to the body of the downhole tool. A valve member according to embodiments of the present disclosure has a number of benefits. For example, since the valve member is freely moveable and does not require any latching or unlatching mechanism to operate, the valve arrangement can move between closed and open configuration repeatedly and/or without the requirement to perform a work-over operation to latch/unlatch the valve member.

The valve member may take a number of different forms.

The valve member may comprise a body portion configured to engage the valve seat. The valve member body portion may be tubular in construction.

The valve member may comprise a centraliser portion. The centraliser portion may be formed on, or coupled to, the body portion of the valve member. The centraliser portion may be configured to engage the tubular member of the downhole tool.

In particular embodiments, the valve member may comprise a first valve member body portion and a second valve member body portion. The first valve member body portion and the second valve member body portion may be configured for coupling together. The first valve member body portion and the second valve member body portion may be configured for coupling by at least one of a mechanical coupling arrangement, such as threaded connection, a quick connector, a weld connection, an adhesive bond or other suitable coupling arrangement. In use, the first valve member body portion may define an upper body portion of the valve member. The first body portion may be configured to engage the valve seat. In use, the second valve member body portion may define a lower body portion of the valve member. The second valve member body portion may comprise, or in particular embodiments may provide mounting for, the centraliser portion of the valve member. Beneficially, the valve member may act as a centraliser or guide for the rod string.

At least one of the valve member body portion and the valve member centraliser portion may comprise a channel to facilitate passage of fluid.

The body may comprise a unitary component.

Alternatively, the body may comprise a plurality of body portions.

The body may comprise a first body portion. The first body portion may define an upper housing of the downhole tool. The first body portion may be tubular. The lateral flow passage may be formed in the first body portion.

The body may comprise a second body portion. The second body portion may define a lower housing of the downhole tool.

The downhole tool may comprise, or may be configured to couple to, a top sub. The top sub may comprise a third body portion of the body.

The downhole tool may comprise, or may be configured to couple to, a bottom sub. The bottom sub may comprise a fourth body portion of the body.

The top sub, upper housing portion, flow tube and bottom sub may together form the axial flow passage of the downhole tool.

As described above, the downhole tool may be operatively associated with a downhole pump.

The downhole pump may take a number of different forms. In particular embodiments, the downhole pump may comprise a positive displacement pump, such as a progressive cavity pump (PCP) or the like. The downhole tool may form part of a downhole pump assembly comprising a downhole pump. The downhole tool may be configured to be coupled to the downhole pump. In particular embodiments, the downhole tool may be configured to be coupled to a stator housing of the downhole pump.

The downhole tool may comprise a connection arrangement for coupling the downhole tool to a tubular string. The connection arrangement may comprise a connector for coupling the downhole tool to an uphole component of the tubular string. In some embodiments, the connector for coupling the tool to an uphole component of the tubular string may be integral to the body. In particular embodiments, the connector for coupling the tool to an uphole component of the tubular string may comprise a separate component, in particular but not exclusively a top sub or the like.

The connection arrangement may comprise a connector for coupling the tool to a downhole component of the tubular string. In some embodiments, the connector for coupling the tool to a downhole component of the tubular string may be integral to the second member. In particular embodiments, the connector for coupling the tool to a downhole component of the tubular string may comprise a separate component, in particular but not exclusively a bottom sub or the like.

At least one of the uphole connector and the downhole connector may comprise a threaded connector or the like. At least one of the uphole connector and the downhole connector may comprise a threaded box connector. At least one of the uphole connector and the downhole connector may comprise a threaded pin connector.

The axial flow passage may comprise a throughbore of the downhole tool.

According to a second aspect, there is provided a method comprising:

providing a downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body; and

operating the downhole tool between a first, closed, configuration in which the downhole tool prevents fluid communication through the lateral flow passage and a second, open, configuration in which the downhole tool permits fluid communication through the lateral flow passage.

The downhole tool may comprise a valve arrangement configured to permit selective fluid communication through the axial flow passage. When the downhole tool defines the second, open, configuration permitting fluid communication through the lateral flow passage, the downhole tool may prevent fluid communication through the axial flow passage. Beneficially, such an arrangement permits fluid to be diverted through the lateral flow passage but prevent back-flow of fluid through the axial flow passage.

The downhole tool may comprise a sleeve member. The sleeve member may be operatively associated with the lateral flow passage. The downhole tool may be configured so that in the first, closed, configuration, the sleeve member prevents fluid communication through the lateral flow passage. The downhole tool may be configured so that in the second, open, configuration the sleeve member permits fluid communication through the lateral flow passage.

The method may comprise running the downhole tool into a borehole as part of a downhole tubing string.

The valve arrangement of the downhole tool may comprise, or may be operatively associated with, a valve member and the method may comprise running the valve member into the borehole. In some embodiments, the valve member may be run into the borehole with the downhole tool. In some embodiments, the valve member may be run into the borehole separately from the downhole tool. For example, the valve member may be run into the borehole on a rotor or rod string of a downhole pump to which the downhole tool is coupled or operatively associated.

The method may comprise directing a treatment fluid from surface or other location uphole of the downhole tool.

According to a third aspect, there is provided a downhole tool comprising:

a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and

a lateral flow passage disposed through the body,

wherein the downhole tool is operable between a first, closed, configuration in which the downhole tool prevents fluid communication through the lateral flow passage and a second, open, configuration in which the downhole tool permits fluid communication through the lateral flow passage, and wherein the downhole tool comprises or is operatively associated with a valve member freely axially moveable relative to the body.

The downhole tool may comprise a valve arrangement configured to permit selective fluid communication through the axial flow passage. When the downhole tool defines the second, open, configuration permitting fluid communication through the lateral flow passage, the downhole tool may prevent fluid communication through the axial flow passage. Beneficially, such an arrangement permits fluid to be diverted through the lateral flow passage but prevent back-flow of fluid through the axial flow passage.

The downhole tool may comprise a sleeve member. The sleeve member may be operatively associated with the lateral flow passage. The downhole tool may be configured so that in the first, closed, configuration, the sleeve member prevents fluid communication through the lateral flow passage. The downhole tool may be configured so that in the second, open, configuration the sleeve member permits fluid communication through the lateral flow passage.

According to a fourth aspect, there is provided a method comprising:

providing a downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body; and

operating the downhole tool between a first, closed, configuration in which the downhole tool prevents fluid communication through the lateral flow passage and a second, open, configuration in which the downhole tool permits fluid communication through the lateral flow passage, wherein the downhole tool comprises or is operatively associated with a valve member freely axially moveable relative to the body.

The downhole tool may comprise a valve arrangement configured to permit selective fluid communication through the axial flow passage. When the downhole tool defines the second, open, configuration permitting fluid communication through the lateral flow passage, the downhole tool may prevent fluid communication through the axial flow passage. Beneficially, such an arrangement permits fluid to be diverted through the lateral flow passage but prevent back-flow of fluid through the axial flow passage.

The downhole tool may comprise a sleeve member. The sleeve member may be operatively associated with the lateral flow passage. The downhole tool may be configured so that in the first, closed, configuration, the sleeve member prevents fluid communication through the lateral flow passage. The downhole tool may be configured so that in the second, open, configuration the sleeve member permits fluid communication through the lateral flow passage.

It should be understood that the features defined above in relation to any aspect, embodiment or arrangement or described below in relation to any specific embodiment or arrangement may be utilised, either alone or in combination with any other defined feature, in any other aspect or embodiment of the disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects of the present disclosure will now be described, by way of example only, with reference to the accompanying drawings, in which:

FIG. 1 shows a downhole tool according to an embodiment of the present disclosure, the downhole tool forming part of a downhole pump assembly;

FIG. 2 shows a side view of the downhole tool shown in FIG. 1;

FIG. 3 is a longitudinal cut away view of the downhole tool shown in FIG. 2;

FIG. 4 is an enlarged view of an uphole section of the downhole tool shown in FIG. 3;

FIG. 5 is an enlarged view of the downhole section of the downhole tool shown in FIG. 3;

FIG. 6 is a longitudinal section view of the downhole tool;

FIG. 7 is a perspective view of a valve member for use with the downhole tool shown in FIGS. 1 to 6;

FIG. 8 is a side view of the valve member shown in FIG. 7;

FIG. 9 is a section view of the valve member shown in FIGS. 7 and 8;

FIG. 10 is a longitudinal cut away view of the downhole tool, in a first configuration and with the axial flow passage closed;

FIG. 11 is an enlarged view of part of the downhole tool shown in FIG. 10, in the first configuration and with the axial flow passage closed;

FIG. 12 is a longitudinal cut away view of the downhole tool, in the first configuration and with the axial flow passage open;

FIG. 13 is an enlarged view of part of the downhole tool shown in FIG. 12, in the first configuration and with the axial flow passage open;

FIG. 14 is a longitudinal cut away view of the downhole tool, in a second configuration; and

FIG. 15 is an enlarged view of part of the downhole tool shown in FIG. 13, in the second configuration.

DETAILED DESCRIPTION

Referring first to FIG. 1 of the accompanying drawings, there is shown a diagrammatic view of a downhole tool 10 according to the present disclosure. In use, the downhole tool 10 is run into a borehole, such as an oil and/or gas production well borehole B, as part of a tubing string S, the downhole tool 10 being configured to permit selective axial passage of fluid through the downhole tool 10 while lateral passage of fluid is prevented, the downhole tool 10 being operable to move from a first, closed, configuration to a second, open, configuration in response to an activation event to divert fluid through the lateral flow passage into an annulus A between the downhole tool 10 and the borehole B.

As shown in FIG. 1, the downhole tool 10 is operatively associated with a downhole pump P, in the illustrated embodiment a progressive cavity pump having a pump stator PS and a pump rotor PR, and as will be described further below, the downhole tool 10 is configured to permit fluid passage from the downhole pump P towards surface or other uphole location via the axial flow passage while preventing back-flow and preventing lateral flow. In the event pump operation ceases, the downhole tool 10 is operable to move from the first, closed configuration to the second, open, configuration to divert fluid uphole of the downhole tool 10 to the annulus A.

Reference is now made to FIGS. 2 to 6 of the accompanying drawings. FIGS. 2 and 3 show side and longitudinal cut away views, respectively, of the downhole tool 10 shown in FIG. 1, while FIGS. 4 and 5 show enlarged views of uphole and downhole sections of the downhole tool 10. FIG. 6 shows a longitudinal section view of the downhole tool 10 in isolation for ease of reference.

The downhole tool 10 has a body 12 having a throughbore 14 which forms an axial flow passage of the downhole tool 10 and a plurality of circumferentially arranged lateral ports 16 which form a lateral flow passage of the downhole tool 10. The downhole tool 10 further comprises a valve seat 18 and a sleeve member 20.

In use, the downhole tool 10 is run into a well borehole B as part of a downhole tubing string S, the valve seat 18 co-operating with a valve member 22 (as will be described further below) to provide selective fluid communication through the throughbore 14 of the downhole tool 10 and the sleeve member 20 being operable to provide selective fluid communication through the ports 16 between the throughbore 14 and the annulus A between the downhole tool 10 and the borehole B.

In the illustrated embodiment, the downhole tool 10 comprises a top sub 24, a body 26 comprising an upper housing portion 28 and a bottom housing portion 30, and a bottom sub 32.

FIG. 4 of the accompanying drawings shows an enlarged view of an upper portion of the downhole tool 10. As shown in FIG. 4, the top sub 24 is generally tubular in construction and forms the uphole end of the downhole tool 10 in use (left end as shown in FIG. 4). The top sub 24 defines a threaded box connector 34 at its upper end for coupling the downhole tool 10 to an adjacent uphole tool, tubing section or component S1 of the string S. It will be understood that while in the illustrated embodiment the top sub 24 defines threaded box connector 34, the top sub 24 may alternatively define a threaded pin connector or any other suitable connector. A lower end portion 36 of the top sub 24 is recessed and is configured to engage an upper end portion 38 of the upper housing portion 28 via a thread connection 40, the top sub 24 and the upper housing portion 28 being secured via a number of circumferentially arranged set screws 42. A groove 44 is also formed in the outer surface of lower end portion 36 and a seal element in the form of o-ring seal 46 is disposed in the groove 44.

The upper housing portion 28 is also generally tubular in construction, the upper end portion 38 of the upper housing portion 28 being disposed on the lower end portion 36 of the top sub 24 while a lower end portion 46 of the upper housing portion 28 is recessed and is configured to engage an upper end portion 48 of the lower housing portion 30 via a thread connection 50, the upper housing portion 28 and the lower housing portion 30 being secured via a number of circumferentially arranged set screws 52. A groove 54 is also formed in the outer surface of lower end portion 46 of the upper housing portion 26 and a seal element in the form of o-ring seal 56 is disposed in the groove 54.

FIG. 5 of the accompanying drawings shows an enlarged view of a lower portion of the downhole tool 10. As shown in FIG. 5, the lower housing portion 30 is also generally tubular in construction, a lower end portion 58 of the lower housing portion 30 is disposed on a recessed upper end portion 60 of the bottom sub 32 and is configured to engage the upper end portion 58 of the bottom sub 32 via a thread connection 62, the lower housing portion 30 and the bottom sub 32 secured via a number of circumferentially arranged set screws 64.

The bottom sub 32 is generally tubular in construction and forms the downhole end of the downhole tool 10 in use (right end as shown in FIGS. 2 to 6). The bottom sub 32 defines a threaded pin connector 66 at its lower end for coupling the downhole tool 10 to an adjacent downhole tool, tubing section or component S2 of the string S. It will be understood that while in the illustrated embodiment the bottom sub 32 defines threaded pin connector 66, the bottom sub 32 may alternatively define a threaded box connector or any other suitable connector. A groove 68 is also formed in the outer surface of the upper end portion 60 of the bottom sub 32 and a seal element in the form of o-ring seal 70 is disposed in the groove 68.

As shown in FIGS. 5 and 6 and referring again also to FIG. 3 of the accompanying drawings, it can be seen that an inner surface of the bottom sub 32 is recessed and provides mounting for a tubular member in the form of flow tube 72, the flow tube 72 coupled to the bottom sub 32 via a thread connection 73. As shown, the flow tube 72 extends in an uphole direction (to the left as shown in FIG. 3) and the upper end of the flow tube 72 forms or provides mounting for the valve seat 18. A plurality of circumferential flow ports 74—which form a lateral flow passage of the flow tube 72—provide fluid communication between the throughbore 14 and a flow gallery 75 which communicates the fluid to the sleeve member 20.

The sleeve member 20 is disposed between the outside of the flow tube 72 and the inside of the body 26. In the illustrated embodiment, the sleeve member 20 comprises an upper sleeve member portion 76 and a lower sleeve member portion 78 coupled together via a thread connection 80, although it will be understood that the sleeve member 20 may alternatively comprise a unitary construction. Grooves 82 are disposed in an inner surface of the sleeve member 20 and bushes—in the illustrated embodiment in the form of PTFE bushes 84—are disposed in the grooves 82. It will be understood that seal elements, such as o-ring seals, may alternatively or additionally be provided between the sleeve member 20 and the flow tube 72. In use, the bushes 84 provide sealing and sliding engagement between the sleeve member 20 and the flow tube 72. A groove 86 is also provided in an outer surface of the sleeve member 20 and a seal element in the form of an o-ring seal 88 is disposed in the groove 86. In use, the seal 88 provides sealing between the sleeve member 20 and the body 26. It will be understood that bushes, such as PTFE bushes, may alternatively or additionally be provided between the outer surface of the sleeve member 20 and the body 26.

A spring element 90 which forms a biasing member of the downhole tool 10 is also provided, the spring element 90—in the illustrated embodiment a coil spring—is secured at its lower end to the bottom sub 32 and at its upper end to the sleeve member 20. In use, the spring element 90 biases the sleeve member 20 to the position shown in FIG. 2, in which the lateral flow ports 16 are closed.

Referring now also to FIGS. 7, 8 and 9 of the accompanying drawings, the valve member 22 takes the form of a floating shuttle valve member 22 having a valve member top sub 92 which forms a body portion of the valve member 22 and a valve member bottom sub 94 which provides mounting for a centraliser portion 96 of the valve member 22 in use. The valve member top sub 92 and the valve member bottom sub 94 are coupled together via a threaded connection 98.

The valve member top sub 92 is generally tubular in construction and in the illustrated embodiment has an integral hard-faced valve surface 100 with a profile configured to match the valve seat 18 provided on the flow tube 72. A collar 102 is located around the top sub 90 and retained by a retention cap 104 that is connected to the top sub 92 via a threaded connection 106, the collar 102 being free to rotate. Two tubular rod bushes (rod guides) 108 are provided, the bushes 108 retained by the base and the retention cap 104.

The valve member bottom sub 94 is also generally tubular in construction, and as described above provides mounting for the centraliser portion 96 having blades 110 for engaging the inside of the flow tube 72.

In use, the valve member 22 is disposed on a rod string 112, which in the illustrated embodiment comprises a polished rod assembly comprises a short length of API polished rod connected to sucker rod couplings 114 (shown in FIG. 3) top and bottom via threaded connections (not shown).

As will be described further below, the valve member 22 and the rod string 112 are deployed and positioned above the rotor PR of the downhole pump P. The valve member 22 is free to move rotationally and axially along the polished rod (as far as the adjacent couplings) of the rod string 112, the rod string 112 sized so that once the rod string 112 has been run to depth and the rotor PR is located within the stator PS of the downhole pump P, the valve member 22 and rod string 112 are located within the body 24 of the downhole tool 10.

Operation of the downhole tool 10 will now be described with reference to all of the accompanying drawings and in particular to FIGS. 10 to 15.

As shown in FIGS. 10 and 11, the downhole tool 10 is run into the borehole B with the tubing string S. As discussed above, during run in and under static/equalised pressure conditions, the lateral ports 16 that allow communication between the throughbore 14 and the annulus A remain closed, maintaining integrity of the string S. This allows the operator to run a conventional tubing string in place of the valve member 22 and rod string 112 and produce the well should this be required.

When the pump P is switched on, the flow pressure will act on the valve member 22, moving the valve member 22 uphole from the position shown in FIGS. 10 and 11 to the position shown in FIGS. 12 and 13, to permit passage of well fluids up the tubing string S. It will be recognised, however, that the lateral ports 16 remain closed.

If the pump P is switched off, the flow pressure will equalise allowing the valve member 22 to move downhole from the position shown in FIGS. 12 and 13 back to the position shown in FIGS. 10 and 11. The valve member 22 will re-seat, shutting off any back flow through the pump P.

It will be recognised that the valve member 22 does not require any latching mechanism, and so the above process may be repeated as often as required.

With the pump P non-operative, the differential head in the tubing string S causes the fluid in the upper string to ‘u-tube’, the resulting pressure acting on the sleeve member 20 which will move downward, opening the lateral ports 16 and diverting the ‘u-tubing’ fluid into the annulus A, along with any entrained solids where they can be transported back to the reservoir (not shown). Beneficially, this prevents any solids from building up on top of the pump P and also prevents backspin from occurring.

Once the differential head in the tubing string S has equalised with the static well pressure or has dropped below a pre-defined level, the sleeve member 20 will move upward automatically, closing off the lateral ports 16 and re-instating integrity of the tubing string S. As described above, the bottom sealing area of the sleeve member is larger than the top sealing area, thus given a static pressure across the sleeve member 20, the sleeve member 20 is biased in the “annular ports closed” position due to static pressure, as well as being mechanically biased by the coil spring.

In situations where the well is at risk of being over-produced, as soon as fluid inflow at the pump P ceases, the resulting pressure differential in the tubing string S will act to close off backflow through the pump P and open the lateral ports 16. The fluid column is again diverted into annulus A and back down to the reservoir preventing the pump P from running dry and mitigating pump-off conditions. Again, once pressure has equalised, the lateral ports 16 automatically close, re-establishing integrity of the tubing string S.

Should a back-flush requirement arise, the operator will stop the pump P and then retract the pump rotor PR from the pump stator PS. As the pump rotor PR is retracted through the valve member 22, the valve member 22 engages and is lifted from the valve seat 18 by a rod string coupling (not shown) and the back-flush operation can commence.

On completion of the back-flush operation, as the pump rotor PR is run back to depth, the valve member 22 will re-seat separating the pump rotor PR/pump stator PS from the upper portion of tubing string S. Pump operation can then recommence as normal.

Should a chemical injection requirement arise, the operator simply pumps the injected chemicals down the tubing string S without retracting the pump rotor PR. The pumped fluids act on the downhole tool 10, axially moving the sleeve member 20 to open the lateral ports 16, to permit the injection fluids to be pumped in to the annulus A and down into the reservoir. Once pumping is complete the lateral ports 16 automatically close reinstating integrity of the tubing string S.

It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto without departing from the scope of the disclosure.

This written description uses examples to disclose the invention, including the preferred embodiments, and also to enable any person skilled in the art to practice the invention, including making and using any devices or systems and performing any incorporated methods. The patentable scope of the invention is defined by the claims, and may include other examples that occur to those skilled in the art. Such other examples are intended to be within the scope of the claims if they have structural elements that do not differ from the literal language of the claims, or if they include equivalent structural elements with insubstantial differences from the literal languages of the claims. Aspects from the various embodiments described, as well as other known equivalents for each such aspects, can be mixed and matched by one of ordinary skill in the art to construct additional embodiments and techniques in accordance with principles of this application. 

What we claim is:
 1. A downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body, wherein the downhole tool is operable between a first, closed, configuration in which fluid communication through the lateral flow passage is prevented and a second, open, configuration in which fluid communication through the lateral flow passage is permitted, the downhole tool being configured to normally define the first, closed, configuration.
 2. The downhole tool of claim 1, comprising a valve arrangement configured to permit selective fluid communication through the axial flow passage.
 3. The downhole tool of claim 1, comprising a sleeve member operatively associated with the lateral flow passage, the downhole tool configured so that in the first, closed, configuration, the sleeve member prevents fluid communication through the lateral flow passage and so that in the second, open, configuration the sleeve member permits fluid communication through the lateral flow passage.
 4. The downhole tool of claim 1, wherein the downhole tool is operable to move from the first, closed, configuration to the second, open, configuration in response to an activation event.
 5. The downhole tool of claim 2, wherein the activation event comprises a fluid pressure force acting on the sleeve member.
 6. The downhole tool of claim 2, wherein the fluid pressure force comprises a differential pressure force acting on the sleeve member between fluid uphole of the sleeve member and fluid downhole of the sleeve member.
 7. The downhole tool of claim 1, wherein the activation event comprises a fluid pressure force resulting from fluid directed through the axial flow passage from surface or other uphole location.
 8. The downhole tool of claim 7, wherein the fluid directed through the axial flow passage from surface or other uphole location comprises a well treatment fluid.
 9. The downhole tool of claim 1, wherein the downhole tool is biased towards the first, closed, configuration.
 10. The downhole tool of claim 9, wherein the downhole tool is biased towards the first, closed, configuration by a biasing member operatively associated with the sleeve member.
 11. The downhole tool of claim 10, wherein the biasing member comprises a spring element.
 12. The downhole tool of claim 9, wherein the downhole tool is biased towards the first, closed, configuration, by fluid pressure.
 13. The downhole tool of claim 1, wherein the sleeve member is configured so that an uphole-directed area of the sleeve member is smaller than a downhole-directed area of the sleeve member.
 14. The downhole tool of claim 1, wherein the downhole tool is operatively associated with a downhole pump.
 15. The downhole tool of claim 14, wherein the downhole pump comprises a positive displacement pump.
 16. The downhole tool 15, wherein the downhole pump comprises a progressive cavity pump.
 17. The downhole tool of claim 14, wherein the downhole tool is configured to be coupled to the downhole pump.
 18. The downhole tool of claim 14, wherein the downhole tool is configured to be coupled to a stator housing of the downhole pump.
 19. The downhole tool of claim 14, wherein the downhole tool forms part of a downhole pump assembly comprising the downhole pump.
 20. The downhole tool of claim 14, when dependent on claim 4, wherein the activation event comprises a fluid pressure force acting on the sleeve member as a result of shut down or a reduction in output from the downhole pump.
 21. The downhole tool of claim 1, wherein the valve arrangement is configured to permit fluid passage towards surface or other uphole location via the axial flow passage while preventing back-flow.
 22. The downhole tool of claim 1, wherein the valve arrangement comprises a valve seat.
 23. The downhole tool of claim 22, wherein the valve seat is formed on, or coupled to, a tubular member forming part of, or which is coupled to, the body of the downhole tool.
 24. The downhole tool of claim 1, wherein the valve arrangement comprises, or is operatively associated with, a valve member.
 25. The downhole tool of claim 24, wherein the valve member is disposed on or coupled to the downhole pump.
 26. The downhole tool of claim 24, wherein the valve member is disposed on a rotor or rod string of the downhole pump, and wherein the valve member is axially moveable relative to the downhole tool in response to fluid flow output from the downhole pump.
 27. The downhole tool of claim 24, wherein the valve member is freely axially moveable relative to the body of the downhole tool.
 28. The downhole tool of claim 24, wherein the valve member comprises a body portion configured to engage the valve seat.
 29. The downhole tool of claim 24, wherein the valve member comprises a centraliser portion formed on, or coupled to, the body portion of the valve member.
 30. The downhole tool of claim 1, wherein the lateral flow passage comprises at least one lateral port.
 31. The downhole tool of claim 30, wherein the lateral flow passage comprises a plurality of lateral ports.
 32. The downhole tool of claim 1, wherein the body of the downhole tool comprises a plurality of components coupled together.
 33. The downhole tool of claim 1, wherein the body comprises a first body portion defining an upper housing of the downhole tool and a second body portion defining a lower housing of the downhole tool.
 34. The downhole tool of claim 33, wherein the lateral flow passage is formed in the first body portion.
 35. The downhole tool of claim 1, wherein at least one of: the downhole tool comprises, or is configured to couple to, a top sub for coupling to an adjacent uphole tool or component of a tubing string; and the downhole tool comprises, or is configured to couple to, a bottom sub for coupling to an adjacent downhole tool or component of a tubing string.
 36. A method comprising: providing a downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body; and operating the downhole tool between a first, closed, configuration in which the sleeve member prevents fluid communication through the lateral flow passage and a second, open, configuration in which the sleeve member permits fluid communication through the lateral flow passage.
 37. A downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body, wherein the downhole tool is operable between a first, closed, configuration in which the downhole tool prevents fluid communication through the lateral flow passage and a second, open, configuration in which the downhole tool permits fluid communication through the lateral flow passage, and wherein the downhole tool comprises or is operatively associated with a valve member freely axially moveable relative to the body.
 38. A method comprising: providing a downhole tool comprising: a body having an axial flow passage therethrough, the downhole tool configured to permit selective fluid communication through the axial flow passage; and a lateral flow passage disposed through the body; and operating the downhole tool between a first, closed, configuration in which the downhole tool prevents fluid communication through the lateral flow passage and a second, open, configuration in which the downhole tool permits fluid communication through the lateral flow passage, wherein the downhole tool comprises or is operatively associated with a valve member freely axially moveable relative to the body.
 39. (canceled)
 40. (canceled) 